flow assurance
DESCRIPTION
deep water flow assuranceTRANSCRIPT
Flow assurance in sub-sea pipelines
www.conservaenergia.com
• MR Riazi, Characterization and Properties of Petroleum Fractions, ASTM International, (2005).• Y Bai and Q Bai, Subsea Pipelines and Risers, Elsevier Science,
2nd Ed, (2005)
Reference Sources used:
Aims & Objectives• to review the types of materials constituting petroleum fluids• to identify and describe the types and the properties of materials which
compromise pipeline flow assurance• to relate how phase equilibria diagrams (PTx) can be used to predict conditions of precipitation of these materials• to consider means to inhibit formation of these materials
1.E+00
1.E+02
1.E+04
1.E+06
1.E+08
1.E+10
0 10 20 30 40
No of carbons
No
of c
ompo
unds
C1
CH4
C2
C2H6
C3
C3H8
methane propaneethane
C4
C4 H10
C4 H8
n-butane
isobutane (methyl-propane)
Hydrocarbon structures
2-methylheptane
C8
n-octane
heteroatom
ethylcyclopentane o-xylene
naphthalene dibenzothiophene
Cycloalkanes
Component Dry Gas Wet gas Gas condensate
Volatile oil Black oil Crude oil+
CO2 3.7 0 0.18 1.19 0.09 0
N2 0.3 0 0.13 0.51 2.09 0
H2S 0 0 0 0 1.89 0
C1 96 82.28 61.92 45.21 29.18 0
C2 0 9.52 14.08 7.09 13.60 0.19
C3 0 4.64 8.35 4.61 9.20 1.88
iC4 0 0.64 0.97 1.69 0.95 0.62
nC4 0 0.96 3.41 2.81 4.30 3.92
iC5 0 0.35 0.84 1.55 1.38 2.11
nC5 0 0.29 1.48 2.01 2.60 4.46
C6 0 0.29 1.79 4.42 4.32 8.59
C7+ 0 1.01 6.95 28.91 30.4 78.23
Total 100 100 100 100 100 100
GOR 69917 4428 1011 855
M7+ 113 143 190 209.8 266
SG7+@ 15.5oC 0.794 0.795 0.8142 0.844 0.895
API7+ 46.7 46.5 42.1 36.1 26.6
From MR Riazi, Characterization and Properties of Petroleum Fractions, ASTM International, p6, (2005).
Composition (mol%) and Properties of Various Reservoir Fluids and Crude Oil*
*measured by analytical tools (gas chromatography, mass spectrometry, etc.)
+stock tank conditions
50 100 150 200 250 400300 350 500450 550
home.flash.net/~acqsol/BatchReport.htm
Infra-red and Near Infra-red spectroscopy
Aske, N, Kallevik, H, and Sjöblom, J., Energy & Fuels, 15, 1304-12, (2001)
Hydrocarbons M H% H/C V d,Å D Insoluble in
Asphaltene 1000-5000 9.2-10.5 1.0-1.4 900 14.2 4-8 n-hexane
Resin 800-1000 10.5-12.5 1.4-1.7 700 13 2-3 80:20 isobutyl alcohol:cyclohexane
Oil 200-600 12.5-13.1 1.7-1.8 200-500 8-12 0-0.7
Pan, H. and Firoozabadi, A., SPE Production and Facilities, 13, pp118-127, (1998)
Petroleum fluid fractions
Increasing molecular weight
Increasing complexity
A knowledge of the composition of a reservoir fluid can enable the phase equilibrium (vapour-liquid and solid-liquid equilibrium) modelling of the pressure – temperature properties of the fluid
www.jee.co.uk
40
200
160
120
80
300 400 700 800Temperature (K)
Pres
sure
(bar
)
240
500 600200
L+V
Lcritical pointdew pointbubble point
C7+ (1 component)
C7+ (5 components)
Pressure–Temperature–Composition (PTx): Effects on Phase Equilibria
• pressure reduction at valves• compositional changes from injection processes• temperature/pressure changes during pipeline transit (flow)
• phase separation (suspended solids agglomerates)• adhesion to transmission control system
• reduction in throughput (revenue)• blockage
There are three types of heavy hydrocarbons that exist in a heavy petroleum fluid which due to PTx effects can precipitate in transmission systems:
• waxes• asphaltenes• resins
Also, interactions between oil/gas constituents and injection media can lead to formation of:
• gas hydrates• salts
www.ifos.com
Waxes (or paraffins)
Pigging to remove wax from a subsea transfer line(http://www.hydrafact.com)
• typically long chain (C6- C36) normal (n-)alkane compounds that are naturally resident in crude oil – average molecular weight around 350 and freezing points in the range 30 – 70oC
• crystalline waxes (iso- and cyclo- paraffins, C30-60, M in the range 500- 800 and melting pt. 70-90oC)• Consistency ranges from petroleum jelly
to hard wax. Density around 0.8 g.cm-3
• can deposit from the oil as a result of temperature/pressure changes (particularly susceptible are sub sea production facilities and pipelines)
• forms as waxy elongated crystals.
Measurement of wax appearance characteristics(http://www.hydrafact.com)
The WAT is not an equilibrium point; wax appearance is a kinetically-controlled nucleation process;
influenced by temperature, (e.g. temperature gradients from wall cooling), cooling rates and availability of nucleation sites (e.g. small particles).
Below the WAT, crystals may form and be transported with the remaining fluid or deposit on a cold surface, leading to fouling.
The pour point is the temperature at which a fluid ceases to pour – the formation of a 3D network spanning the pipe - can occur when flow is interrupted.
Wax deposition characteristics
In subsea systems:• wax deposition in pipelines is gradual but can lead to blockage• crude oil gelation can occur during shut-in (zero flow)• leads to high start-up pressures and high pumping pressures due to increased viscosity• temperature gradients can be reduced by insulating pipes (increased capital expense)
The temperature at which wax begins to form is called the ‘cloud point’ or the wax appearance temperature (WAT).
Wax precipitation models• solid solution • multisolid phase model – calculation of cloud point temperature (CPT) – equivalent to WAT
Both models are based on the relationship:
),,(),,(),,( Si
Si
Li
Lii
Vi xPTfxPTfyPTf
iii xKy and Li
SLi
Si xKx
WAT values derived from solid solution models are close to the pour points of oilWAT values derived from multisolid phase models are close to the cloud point
Pan, H., Firoozabadi, A and Fotland, P., SPE Production and Facilities, 12, 250-8, (1997)
Effect of temperature and Pressure on WAT
VLE SLE
Wax InhibitionCloud points for crude oils are generally in the range 300-315K (80-110oF)Protection strategies may include:
• temperature control at CPT + 15oF• readily achieved in the wellbore and subsea tree• subsea flowlines may require electric or hot fluid heating
• thermodynamic wax inhibitors (TWI), e.g. solvents • polyalkyl acrylates, low molecular weight polyethylene waxes, ethyl-vinyl acetate (EVA) • wax-saturated solvents must be removed to avoid re-precipitation elsewhere
• pour point depressants/dispersants/surfactants• modify crystal structure and reduce viscosity, i.e. additives with wax-like (n-alkane) part to bind the wax but non-wax-like terminating group as in surfactants, e.g. linear sulphonates.
EVA
Remediation strategies:• mechanical – pigging.• NGS (nitrogen generating system) – combines thermal, chemical, and mechanical effects by controlling nitrogen gas generation to comprise the reversible fluidity of wax/paraffin deposits
dispersant/crystal modifier properties
Asphaltenes
Pipeline asphaltene fouling(http://www.hydrafact.com)
• a black, brittle component of the bitumen in petroleum
• organic materials consisting of aromatic and naphthenic ring compounds which carry the main inorganic components of crude oil,
including nitrogen, sulfur, oxygen, nickel and vanadium
• insoluble in non polar solvents but soluble in toluene or other aromatics-based solvents.
• frequently occurs with wax deposition
• generated as a result of pressure drop, high shear (turbulent flow), acids, soluble CO2 (EOR), injected condensate, mixing of incompatible crudes, etc.
• deposition is non-reversible, i.e. difficult to remove by manipulation of pressure/ temperature. • colloidal suspensions in resins in the oil. Dispersion stability depends on the ratio
of resin to asphaltene molecules.
Molecular Structure of asphaltene proposed for 510C
Residue of Venezuelan Crude by Carbognani [INTEVEP S.A.
Tech. Rept., 1992]
Molecular structure of asphaltene proposed for Maya crude (Mexico) by Altamirano, et al. [IMP
Bulletin, 1986]
Various shapes of asphaltene micelles formed in the presence of large amounts of polar or aromatic
solvents
http://tigger.uic.edu/~mansoori/Asphaltene.Molecule_html
Asphaltenes – molecular characteristics
Pan, H. and Firoozabadi, A., SPE Production and Facilities, 13, pp118-127, (1998)
Rapid physical methods of assessing asphaltene on-set
• refractive index• electrical conductivity• kinematic viscosity…..
500
2500
2000
1500
1000
25 50 75 100
Mole % CO2
Pres
sure
(psi
)
LL
LV
Tank Oil specifications Asphaltene specifications
Mol% C1+ C2 0.6 Wt% resin in oil 14.1
Mol% C3 - C5 10.6 Wt% asphaltene in oil 4.02
Mol% C6 4.3 Density (g/cm3) 1.2
Mol% C7+ 84.5
M 221.5 (M7+ = 250) M (precipitated) 4500
SG 0.873 (SG7+ = 0.96)
900
1300
1200
1100
1000
98 98.5 99 100
Mole % CO2
Pres
sure
(psi
)
99.5
1400
L
LS
LVSLV
Px diagram for an oil-CO2 system at 24oC
Kawanaka, S., Park, SJ, and Mansoori, GA, SPE Reservoir Engineering, 6, 185-192, (1991)
- asphaltene precipitation predicted in LS and LVS fields
Relevance of Equilibrium Phase Diagrams to asphaltene management
Region of asphaltene precipitation
asphaltene solubility
saturation pressure
reservoir pressure
Temperature
Pres
sure
P-T diagram for asphaltene precipitation predictions
Relevance of Equilibrium Phase Diagrams to asphaltene management
Once formed – difficult to remove by manipulation of PT conditions• chemical treatments
Y Bai and Q Bai, Subsea Pipelines and Risers, Elsevier Science, 2nd Ed, 2005
Asphaltene precipitation from tank oil in presence of C5-C10 diluents at 295K and 1 bar.
Tank Oil specifications Asphaltene specifications
Mol% C1+ C2 0.6 Wt% resin in oil 14.1
Mol% C3 - C5 10.6 Wt% asphaltene in oil 4.02
Mol% C6 4.3 Density (g/cm3) 1.2
Mol% C7+ 84.5
M 221.5 (M7+ = 250) M (precipitated) 4500
SG 0.873 (SG7+ = 0.96)
Pan, H. and Firoozabadi, A., SPE Production and Facilities, 13, pp118-127, (1998)Wu, J., Prausnitz, JM, and Firoozabadi, A., AICE Journal, 44, 1188-99, (1998)
Micelle–based model of asphaltene precipitation (and dissolution)
resins
• Onset of asphaltene precipitation shown where curve levels off
• Lighter solvents cause higher precipitation• Dilution ratio (RS, i.e. the volume in cm3/g of
crude) at the onset is a function of solvent molecular weight, MS, i.e. increases with MS
• The amount of solid precipitated in the presence of propane increases with temperature but decreases for n-heptane.• Effect of pressure above the bubble point of
oil decreases precipitation but below, precipitation increases.
propane n-heptane
Effects of chemical treatments on asphaltene solubility
Strategy is to maintain asphaltenes in the fluid (dispersed or solubilised state)
Natural Gas Hydrates
Gas hydrates removed from a subsea transfer line (courtesy of Petrobras, Brazil).
• formed at high pressure and low temperature from combination of water and constituents of hydrocarbon fluid stream (e.g. CH4, C2H6, C3H8, N2, CO2, H2S)• increasingly important in O&G operations in deeper waters• most commonly encountered during
drilling and production
One volume of this saturated methane hydrate contains up to 189 volumes of methane gas at STP. This large gas-storage capacity of gas hydrates may represent an important source of natural gas.
www.csiro.au/files/files/pl1k.pdf A gas hydrate
Image courtesy U.S. Geological Survey
Hydrate Formation Requires Five Ingredients:
Water
Pressure
Temperature
Nucleation Site
Gas - CH4, CO2, C2H6, H2S, etc.
Hydrate Structures - variable
http://www.telusplanet.net/public/jcarroll/HYDR.HTM
http://www.telusplanet.net/public/jcarroll/HYDR.HTM
Hydrates Formation and Dissociation
Stable Hydrate Region
Hydrate-free Region
Metastable Region
hydrate dissociation
curve
hydrate formation
curve
Pre
ssur
e (p
si)
Temperature
Stable Hydrate Region
Hydrate-free Region
Metastable Region
hydrate dissociation
curve
hydrate formation
curve
Pre
ssur
e (p
si)
Temperature
Hydrate Inhibition• Inhibitors (10-50 wt%) can reduce hydrate formation temperature (HFT) to
below the hydrate dissociation curve.• Low dose hydrate inhibitors (LDHI 0.3- 0.5 wt%) – interfere with crystallisation.• Cold flow technology – controlled growth
of hydrates to unsure stable suspensions.
)100( WMKWT
T- temperature shift (oC)W – inhibitor concentration (wt%)M – molecular weight of inhibitor/molecular weight of water
Inhibitor K Value
Methanol 2335
Ethanol 2335
Ethylene glycol 2700
Diethylene glycol 4000
Triethylene glycol 5400
Low dose hydrate inhibitors
• hydrate surface has open cavities – penetrated by hydrocarbon component• amide group hydrogen bonds to hydrate surface via carbonyl• adhesion to hydrate surface prevents further hydrate growth• limited growth keeps hydrates in suspension
Tutorial Questions
1. Identify factors during fluid transfer from a wellbore which can lead to precipitation and conductivity problems in flowlines.
2. Sketch the basic features of a PT diagram for the methane-water system and describe the effect of sub-cooling. Use the diagram to illustrate why this presents a threat to the integrity of a sub-sea flow line.
3. Explain why dehydration is a possible approach to the inhibition of natural gas hydrates in a pipeline and what type of chemical treatment might be suitable.
4. How do low does hydrate inhibitors (LDHIs) function in comparison to thermodynamic hydrate inhibitors (THIs).
5. Discuss the benefits of dispersion over dissolution in the remediation of flow.6. Discuss the role of resins in maintaining flow where there is a realistic risk of
asphaltene precipitation. What specific properties do these have which enable this function?
7. Distinguish between the various constituents of a petroleum fluid and explain the chemical principles involved in defining a remediation treatment for fouled valvework and pipelines.
8. Identify an equilibrium thermodynamics approach to predicting precipitation under various PTx conditions, i.e. how to construct a PTx phase diagram.